For existing oil refineries, the high cost of conventional, light sweet, crude oils has led refiners to consider retrofits with partial replacement of conventional crude oils with price-discounted heavy, corrosive (organic acids), contaminant laden (organic metals, polar heteroatoms, etc.) carbonaceous material more commonly referred to as “Opportunity Crude”, such as those offered from extensive reserves in Western Canada, Latin America, China, Russia, North Sea and elsewhere.
Many refiners have performed such retrofits by co-mingling or blending Opportunity Crude with conventional crude and requiring extensive modifications to almost every refinery process unit to deal with changes in the unit feed composition (e.g., boiling range, molecular structure, etc.) and level of contaminants (e.g., metals, sulfur, nitrogen, organic acids, etc.).
Declining markets for high sulfur fuel oil and asphalt, combined with shifting to heavier feedstock materials, have resulted in the need for heavy residual oil upgrading technologies, such as delayed coking, to reduce the yield of high sulfur fuel oil/asphalt and increase the yield of products in the range of liquid transportation fuels.
The combination of extensive retrofit costs and inefficient application of heavy residual oil upgrading often leads to an extremely high project capital cost, which may not justify the investment decision to introduce the Opportunity Crude into an existing refinery. This situation is likely to continue for an extended period of time on a worldwide basis.
A typical and conventional crude (e.g., low sulfur, low metals, low naphthenic acid, high API gravity, etc.) refining system 100 is illustrated in FIG. 1. This conventional system may be considered as a candidate for replacement of a portion of the refinery's conventional crude with a similar volume of lower quality Opportunity Crude. Many other conventional crude configurations are possible, however, which may benefit from the present invention. Thus, FIG. 1 is just one example of a conventional crude configuration that may benefit from the present invention. In order to realize the benefits of a low cost Opportunity Crude, the capital cost of equipment modifications and additions must represent an acceptable return on investment and the yield and quality of refined products must meet market demand goals and product quality specifications. Unfortunately, prior art systems have been insufficient to do so or have required extensive modifications.
In operation of a typical and conventional crude refining system, conventional crude is routed through Desalting and Preheat Units 102, a Fired Heater Unit 103 (which may be an atmospheric crude fired heater), an Atmospheric Crude Distillation Tower 104, a Fired Heater Unit 105 and a Vacuum Distillation Tower 106 to produce a number of product fractions. As all are of equal importance in the process, no single product or product fraction is generally considered the principal product, rendering the others “by-products;” however, to the extent any one product is considered the principal product, such as gasoline, the others may be considered “by-products” of the process of gasoline production and thus, the terms “product” and “byproduct” may be used synonymously herein. The Atmospheric Crude Distillation Tower 104, the Fired Heater Unit 105 and a Vacuum Distillation Tower 106 separate the conventional crude into fractions by boiling range, such that each fraction becomes a suitable feed stock for downstream conversion and treating process units.
Products separated by the Atmospheric Crude Distillation Tower 104 include light gases, light naphtha (typically C5-180° F. boiling range as gasoline blend stock), and heavy naphtha (typically 180°-400° F. boiling range), which may be provided as a feed stock to the downstream Catalytic Hydrotreating and Catalytic Reforming Unit 110. Light gases are separated from naphtha in the Gas Recovery Unit 108. Products of the Gas Recovery Unit 108 include C3-C4 Liquefied Petroleum Gas (LPG) and refinery fuel gas, which may be burned in refinery furnaces.
Heavy naphtha undergoes contaminant sulfur/nitrogen removal and molecular rearrangement to increase gasoline octane in the Catalytic Hydrotreating and Catalytic Reforming Unit 110. Reformed heavy naphtha becomes a gasoline blend stock.
Another product of the Atmospheric Crude Distillation Tower 104 is kerosene. Kerosene (typically 380°-550° F. boiling range) is drawn from the Atmospheric Crude Distillation Tower 104 and routed to Kerosene Treating Unit 112. Treated kerosene (e.g., low mercaptan sulfur, high smoke point, etc.) may be sold as commercial kerosene or, with suitable freeze point, aromatics concentration, gum, and flash point, as jet engine fuel.
Another product of the Atmospheric Crude Distillation Tower 104 is diesel. Diesel (typically 500°-680° F. boiling range) is drawn from the Atmospheric Crude Distillation Tower 104 and routed to the Diesel Hydrotreating Unit 114. Catalytic hydrotreating reduces sulfur content to meet ultra low sulfur diesel specifications for on-road transportation fuel service.
Heavy atmospheric gas oil (typically 650°-750° F. boiling range) is drawn from the Atmospheric Crude Distillation Tower 104 and routed to the Fluidized Catalytic Cracking Unit 116.
High boiling (typically, 650° F. and higher) atmospheric residue from the bottom of the Atmospheric Crude Distillation Tower 104 flows through the Fired Heater Unit 105 and the Vacuum Distillation Tower 106.
Products of the Vacuum Distillation Tower 106 are vacuum gas oils (typically 625°-1,000° F. boiling range), which are provided as a feed stock to the Fluidized Catalytic Cracking Unit 116, and vacuum residue (typically 1000°+F.), which may be used as high sulfur fuel oil or asphalt.
Vacuum gas oils are routed to the Fluidized Catalytic Cracking Unit 116, which may or may not include a catalytic hydrotreating pre-treatment step. In the fluidized catalytic cracking process, higher boiling vacuum gas oils are cracked into more valuable diesel and gasoline boiling range products. Byproduct LPG and fuel gas are recovered and separated within the Fluidized Catalytic Cracking Unit 116. The diesel product becomes a feed stock to the Diesel Hydrotreating Unit 114, while the gasoline product is routed to the Gasoline Hydrotreating Unit 118 for sulfur removal to meet specifications for low sulfur gasoline.
The most common prior art configuration and technical basis for replacing a portion of the refinery's conventional crude with a similar volume of lower quality Opportunity Crude is illustrated in FIG. 2, an exemplary prior art process 200, particularly for purposes of comparison.
In FIG. 2, conventional crude and Opportunity Crude compose a blended feed stock referred to as “Opportunity Crude Blend” for this system 200 rather than using only conventional crude. Conventional crude and especially Opportunity Crude contain salts, sand, clay and sediments that could foul exchangers and certain material can poison downstream catalysts. Salts are frequently present in the form of Calcium, Sodium and Magnesium Chlorides. The high temperatures that occur downstream in the system 200 could allow the formation of corrosive hydrochloric acid. Therefore, the first step is to feed the Opportunity Crude Blend through a desalter where salts, suspended solids and free water are removed at low temperatures before this feed stock is preheated in a series of heat exchangers and a fired heater. Having a higher proportion of Opportunity Crude in the Opportunity Crude Blend will raise the specific gravity, lower the API gravity, and increase the viscosity and salt content of the material passing through the Desalting and Preheat Units 202. These factors will make desalting more difficult, resulting in the need for more desalting capacity to increase residence time and facilitate oil/water separation, along with higher operating temperature and pressure, to suppress vaporization. As the operating conditions of the Desalting and Preheat Units 202 will also become inadequate for the new function, a replacement desalter, capable of higher temperatures and with a higher mechanical design pressure must be considered.
A Fired Heater Unit 203 associated with the Atmospheric Crude Distillation Tower 204 may be used to heat up the Opportunity Crude Blend to a desired temperature (between 650°-700° F. depending on the type of feed stock) before it enters an Atmospheric Crude Distillation Tower 204. Opportunity Crude with high Total Acid Number (“TAN”) (particularly high naphthenic acid content) are corrosive, particularly in the temperature range between 450°-700° F., wherein the naphthenic acids are concentrated. The preheat exchangers piping and surface areas as well as the furnace tube metallurgy operating in this temperature range therefore, must be upgraded in the Atmospheric Crude Distillation Tower 204.
The Opportunity Crude Blend is flashed off in the Atmospheric Crude Distillation Tower 204, which uses pumparound cooling loops to create an internal liquid reflux. Product draws are on the top, sides, and bottom. The Atmospheric Crude Distillation Tower 204 operates on a descending temperature profile from bottom up as reflux from the top of the Atmospheric Crude Distillation Tower 204 provides the cooling medium while the Fired Heater Unit 203 in the bottom of the Atmospheric Crude Distillation Tower 204 provides heat to boil up product distillates. From the top of the Atmospheric Crude Distillation Tower 204, at any point where the temperature may exceed 450° F., column trays and their internals must be replaced with higher metallurgy material. Since the bottom portion of the Atmospheric Crude Distillation Tower 204 would be operating at higher temperatures (between 650°-700° F. depending on the type of feed stock) and exposed high TAN corrosive attacks, the lower shell of the Atmospheric Crude Distillation Tower 204 may be insufficient absent some modification, to provide alloy lining or a weld overlay.
The reduced crude exiting the bottom of the Atmospheric Crude Distillation Tower 204 is heated in a Fired Heater Unit 205 before being routed to the and the Vacuum Distillation Tower 206 to recover any gas oil from the reduced crude. Product draws are on the top, sides, and bottom. The Vacuum Distillation Tower 206 operates on a descending temperature profile from bottom up as reflux from the top of the Vacuum Distillation Tower 206 provides the cooling medium while a Fired Heater Unit 205 in the bottom of the Vacuum Distillation Tower 206 provides heat to boil up product vacuum gas oils.
Light products from the top of the Atmospheric Crude Distillation Tower 204 are sent to a Gas Recovery Unit 208 to separate fuel gas from LPG.
Full range naphtha recovered from the Atmospheric Crude Distillation Tower 204 is separated into light and heavy fractions. Light naphtha is sent for gasoline blending while heavy naphtha is processed through a Catalytic Hydrotreating and Catalytic Reforming Unit 210 to become a high octane gasoline component.
A kerosene product from the Atmospheric Crude Distillation Tower 204 is sent to a Kerosene Treating Unit 212 to remove sulfur and mercaptans. To produce jet fuel, a certain level of aromatic saturation needs to take place in order to make the smoke point specifications of jet fuel material.
A diesel product from the Atmospheric Crude Distillation Tower 204 and light gas oil from the Delayed Coker Unit 220 are combined and hydrotreated in a Diesel Hydrotreating Unit 214 to remove sulfur. In this process, the operating conditions and catalyst space velocity are selected in order to ensure both sulfur removal and a high cetane index number to meet the required specifications for Ultra Low Sulfur Diesel. These units may need to be modified from a conventional design using techniques well known in the art to manage the higher feed rates as conventional diesel hydrotreating unit reactors are not of sufficient size to address the higher feed rates and higher operating temperatures.
Atmospheric gas oil from the Atmospheric Crude Distillation Tower 204, vacuum gas oil from the Vacuum Distillation Tower 206 and heavy gas oil from the Delayed Coker Unit 220 pass through a Fluidized Catalytic Cracking Unit 216 to be further converted to lighter products. These products range from LPG, naphtha, LCO and slurry oil. With the use of Opportunity Crude, feeds to the Fluidized Catalytic Cracking Unit 216 are expected to contain higher level of contaminant requiring a higher catalyst replacement rate.
A gasoline product from the Fluidized Catalytic Cracking Unit 216 is routed to the Gasoline Hydrotreating Unit 218 to remove sulfur down to 30 or 10 ppm with minimum octane loss.
A vacuum resid from the bottom of the Vacuum Distillation Tower 206 is sent to the Delayed Coking Unit 220, which also includes gas recovery and naphtha hydrotreating units, in order to convert this resid material to lighter products, such as light gas oil and heavy gas oil while minimizing LPG production.
Various other modifications have explored replacing a portion of the refinery's conventional crude with a similar volume of lower quality Opportunity Crude such as, for example, that disclosed in U.S. Patent Application Publication No. 2010/0206773 A1, U.S. Patent Application Publication No. 2010/0206772 A1, and U.S. Patent Application Publication No. US 2004/0164001 A1. These, however, have utilized expensive conversion methods for the opportunity crude, with associated higher capital expenditure and higher operating costs, and did not explore the use of delayed coking for conversion.
The prior art therefore, is limited by processing conventional crude and opportunity crude in a combined stream or train, which exposes components to corrosive crude constituents, destroying them over time.